The invention relates to a steam foam process for producing a relatively low gravity acidic oil from a subterranean reservoir. More particularly, it relates to an improved alkali-enhanced steam foam drive or soak process for recovering such oil.
The present invention relates to an improved alkali-enhanced steam foam oil recovery process such as the process described in my commonly assigned U.S. Pat. No. 4,609,044, the disclosures of which are incorporated herein by reference.
Numerous aqueous alkaline flood processes have been proposed, and various processes involving injecting an aqueous alkaline solution and various preformed surfactants have been described in U.S. patents such as the following: U.S. Pat. No. 3,777,817 describes injecting an aqueous alkaline solution to satisfy the surfactant adsorption sites on the reservoir rock and then injecting a surfactant-containing aqueous liquid which may also contain alkali. U.S. Pat. Nos. 3,804,171 and 3,847,823 describe injecting aqueous alkaline solutions containing overbased petroleum sulfonate surfactants which are formed by over-neutralizing petroleum hydrocarbon sulfonates. U.S. Pat. Nos. 3,977,470 and 4,004,638 describe injecting an aqueous alkaline solution followed by an aqueous alkaline solution which contains a preformed surfactant which can be substantially any hydrocarbon sulfonate and can be accompanied by polyphosphates and carbonates that enhance the oil displacing efficiency of the process. U.S. Pat. No. 4,099,569 describes a staged process for recovering oil from a subterranean reservoir by injecting a surfactant solution in which the concentration of the surfactant is increased as increasing amounts of the solution are injected, then injecting a drive fluid. U.S. Pat. No. 4,232,737 describes a staged injection of a highly saline aqueous petroleum sulfonate surfactant system containing a solubilizing amount of cosurfactant and decreasing the concentration of both the salt and surfactant in stages to provide a trailing-edge salinity which is suitable for a polymer thickened aqueous drive fluid. U.S. Pat. No. 4,502,541 by J. B. Lawson and D. R. Thigpen, describes a cosurfactant-aided aqueous alkaline oil recovery process in which an oil displacing fluid containing at least one each of dissolved alkaline material, a substantially neutral salt and a preformed cosurfactant is injected with a concentration gradient such that the initially injected portion of fluid contains a larger proportion of preformed cosurfactant than later injected portions.
Commonly assigned U.S. patent application Ser. No. 411,779, filed Aug. 26, 1982 by D. R. Thigpen, J. B. Lawson and R. C. Nelson (i.e. the "'779 application"), now abandoned, relates to recovering oil from an acidic oil reservoir by injecting an alkaline aqueous solution. In the process of the '779 application, the alkaline solution also contains a substantially neutral salt and a preformed cosurfactant. It uses a cosurfactant comprising at least one compound which is significantly soluble in both the aqueous solution and the reservoir oil while being more soluble in the aqueous solution (relative to its solubility in the reservoir oil) than are the petroleum acid soaps which can be formed from the reservoir oil. The cosurfactant solution is selected and its concentration is adjusted so that the injected solution has an alkalinity, salinity and preformed cosurfactant content such that the salinity of the surfactant system formed by the interaction of the injected solution and the reservoir oil is substantially optimum for minimizing interfacial tension between the oil and surfactant system. The disclosures of the '779 application are incorporated herein by reference.
As indicated in the '779 application, although prior processes in which preformed surfactants were included in injected aqueous liquid solutions were designed to improve the oil recovery efficiency of similar processes free of the preformed surfactants, a serious problem remained in either type of such prior processes. Whenever an aqueous alkaline solution is injected into an oil reservoir, some or all of the alkali may be consumed by chemical reactions other than the desired reaction of converting petroleum acids to surfactant saops. For example, multivalent cations dissolved in the water in the reservoir and/or associated with clay or other reservoir rock material can rapidly consume alkali by forming and precipitating multivalent metal hydroxides or salts. In siliceous reservoirs significant proportions of alkali are consumed by dissolving silicon oxide and by forming alkali metal silicates, etc. Because of such side reactions, if the injected aqueous alkaline solution is dilute, the alkali will propagate slowly through the reservoir rocks. The frontal propagation rate is slow because, as each portion of the injected solution contacts fresh portions of rock, some or all of its alkali content may be consumed by the side reactions. This is repeated over and over, and thus, although the unreactive liquid components of the injected solution may move through the reservoir at the rate corresponding to the rate at which the solution was injected, the movement through the reservoir of the alkali may be much slower. For example, it is disclosed in SPE Paper No. 8995 by Bunge et al that, when an aqueous alkaline solution containing 0.44% sodium hydroxide and 1.0% sodium chloride was flowed through a core of Wilmington sand which initially contained 1.0% calcium chloride solution; more than two pore volumes of the aqueous alkaline solution had to be injected before any of the sodium hydroxide reached the outflow end of the core.
With respect to steam drive or soak processes for recovering oil, various uses of alkali have been proposed. Such proposals are contained in U.S. Patents such as the following. U.S. Pat. No. 3,853,178 suggests adding about 0.05 to 0.1 percent of alkali metal hydroxides to the liquid phase of steam to react with connate water (Col. 2, line 67) or boiler feed water (Col. 3, line 24) to form surface active agents. U.S. Pat. No. 3,924,683 suggests conducting a steam soak process with "very small amounts" (Col. 1, line 41) of alkali, preferably from 0.05 to 0.6 percent (Col. 2, line 62) added to the steam.
In addition, during the generation of steam in the field, the liquid effluent from the steam generator may have a high pH. This is because bicarbonate ions in the steam generator feedwater decompose to CO.sub.2 and hydroxide ions. The CO.sub.2 partitions into the vapor phase and the OH.sup.- ions partition into the liquid phase thus raising the solution pH. The pH of liquid effluents from steam generators in the San Joaquin Valley have been reported to range from 10.8 to 11.6. It is therefore conceivable that, to some extent, in such steam soaks or steam drive processes in heavy-crude oil reservoirs, alkaline floods may be taking place. However, such alkaline floods have little if any effect since their alkalinity is largely confined to the small regions near the injectors; because of the high alkali consumption and the non-optimum conditions for an alkaline flood process.
Alkali metal carbonate salts, particularly the bicarbonate salts, are known to have demonstrated or proposed effects of various types in connection with steam heated thermal drives or soaks. For example, U.S. Pat. No. 3,690,376 by R. W. Zwicky relates to recovering hydrocarbons from underground formations containing mixtures of the hydrocarbons with aqueous solutions of polyvalent metal salts. A steam composition containing a basic salt and a sequestering agent is injected, using a sequestering agent comprising a chelating or precipitating material such as alkali metal sulfates, sulfides, or the like, and using a basic salt comprising an alkali metal carbonate or bicarbonate. The presence of the carbonate and sequestering agent are said to function synergistically to form an emulsifiable mobility front capable of preventing steam fingering. U.S. Pat. No. 4,572,296 relates to a reservoir steaming process for inhibiting the dissolution of silica from the reservoir rock or a gravel pack where the boiler feed water contains bicarbonate ions and forms CO.sub.2 that partitions into the gas phase while hydroxyl ions remain in the liquid phase and increase the alkalinity. An ammonium ion-containing compound is added so that ammonia partitions into the gas phase while hydrogen chloride remains in the liquid phase and counteracts the increase in alkalinity.